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tv   [untitled]    March 26, 2014 1:00am-1:31am PDT

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customer base and where we receive our -- the lion's share of our funding, this slide shows on the left that same set of retail general fund customers. but instead of showing it in the megawatt hour or revenue picture, this is showing it based on the rates that they're charged. so, you can see that the general fund is charged 4.75 cents a kilowatt hour right now typically, there are some that are charged less, but generally speaking it's 4.75 cents a kilowatt hour. you can see our enterprise department customers are charged on average around 14 cents. then you see the black line on the bottom, shows the transmission and distribution costs that were charged by pg&e that we pay today at 1.8 cents a kilowatt hour. that's one of the cost element that builds our cost profile. when you add all of our cost profile elements up, it's around an average cost of about 10 cents. so, you can see that top black
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line shows that when we're selling to a retail enterprise department customer, we have some contribution above our costs. on this slide it's estimated at about 4 cents a kilowatt hour. when we're selling to a general fund department customer, we're selling well below our cost. we are expecting that transmission and distribution cost element to increase. we have been forecasting increases in our budget planning for a number of years now because we are seeing the end of our long-term agreement we had with pg&e for distribution and transmission services. that agreement is referred to as the interconnection agreement or commonly it's referred to the ia from 1978, expires in july of 2015. with that expiration, we expect to see our transmission and distribution rate rise to the
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red line, the red dash line you see here at about 3.4 cents a kilowatt hour. we are in ongoing conversations, ongoing litigation, regulatory proceedings that influence what that number ultimately will be, but that is the number that's currently in effect. so, if we were to roll off of our interconnection agreement today, we would jump from a 1.8 cent a kilowatt hour transmission distribution cost to a 3.4. i'm highlighting this because it's one of the costs that, although we were anticipating a change, it's coming in higher than we had anticipated. and, so, that's one of the factors that's a challenge as we look forward on our financial plan. >> you said that this rate, 3.4, that will be in july 2015 is in effect? does that mean there are plans in place that's what it would fall back to regardless of negotiation -- if negotiations aren't settled? >> no, what i am referring to is the transmission rates that are charged on pg&e's system
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are set by the california independent system operator and ferc. those rates are known today and it's a postage stamp rate that anyone would pay. so, we know that. we are exempt from paying those rates right now because we have this special agreement with pg&e. but we know when that agreement rolls off, we could be subject to that same rate that everybody else is being charged. so, that's actually effective today. with respect to the distribution component -- >> hang on just a second. i'm sorry. we wouldn't expect it to be higher because we wouldn't pay a rate higher than the independent operator says we should. >> right, [speaker not understood], right now we're estimating that to be -- component of it to be in this add up that gets to 3.4 -- >> could it be less? could we expect we would be able to negotiate something that is, you know, comparable to what we've already been paying so we wouldn't go up to 3.4? >> so, we're not, we're not
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giving up on that effort. [multiple voices] >> there is a rate setting process that would -- that indicates what the rate is that's paid by most people. we've had a special arrangement historically. yes, we would like to try to continue to have a special arrangement and we're working with pg&e to try to get there. it's the subject of negotiation. >> and a are there regulatory factors that would influence our hand? ~ to be stronger? >> so, can i jump in? so, one of the things that we're trying to identify, one of the challenges, and some of the challenges are time sensitive and this is one because we know in 2015 it expire. so, we're meeting with our commissioner, with the mayor's office, with the city attorney. we have a working task force to
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really dive in to see how we can minimize this impact. so, we've been actively pursuing this and it's like all hands on deck. so, this is only one element, but we have -- looking at each one of those com poets, we have a team of folks trying to address it. ~ components >> thank you. >> and, so, that's with respect to the transmission component. the distribution component similarly, it's in a contract now. you asked, commissioner, whether it was in effect. pg&e has gone to their regulator on distribution rates, the federal energy regulatory commission, and asked for a rate increase relative to what they charge other of their distribution customers. >> is that what pg&e does very often, ask for a rate increase? i'm just joking. [laughter] >> thank you. the process at the federal energy regulatory commission
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for a distribution rate like this is to allow it to go into effect subject to refund. so, if we weren't protected from the standard rate that pg&e charges others, this is the rate we would be charged today. as i say, it's subject to refund. we're actively participating together with city attorney in the case at ferc, trying to make sure that we pay our fair share and no more for distribution services. >> so, we have full support in that. >> the other thing i wanted to illustrate is that most of our customers in the retail side, we charge equivalent to pg&e. and, so, with the transmission and distribution, they're not raising -- the pg&e doesn't typically raise their rate, per se. they're just raising their rate for transmitting our power through their system and distributing it. so, really, it eats into the
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margin. and, so, instead of paying them 1.2, we're paying 3.4 and we're still charging the same amount. and, so, that's the challenge. >> so, prior to some of these challenges coming into effect, we had a balanced plan. if you pretend you're in february of 2013, the last time we presented a balanced financial plan, fiscal year-end '16 would look like the slide you see in front of you now, where our operating costs would have increased. our capital program would still be quite robust. and we would not be dipping into reserves, but rather, we would be enjoying the proceeds of a debt financing to pay for a share of our capital improvements. so, that was the plan for
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hetchy power after our last correction -- corrective action to bring our plan back into balance. >> could you briefly describe what was the financing, what it looked like? >> so, you can see the financing proceeds here. our plan was to go out to our rating agencies with the first-ever hetchy power plan of finance, get a rating, and be out in the market just like the wastewater and water enterprises are funding their capital programs through debt financing. >> we've never done that before? >> no. >> so, [speaker not understood] 2003, is that correct? >> the voters gave the go ahead ~ for spending up to 100 million in revenue bonds. we have -- we have done some modest revenue bond financing.
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and by modest, i mean we took advantage of some of the federally sponsored programs. we didn't have our own independent credit rating and a plan of finance behind that. and it's very modest in comparison to what we were proposing to do under this plan. even this plan is quite modest compared to water and wastewater are doing at the puc. it shifts us into that more standard utility practice of having a credit rating and borrowing to fund the long-lived assets we rely on to provide service. >> just trying to figure out why we've never done this before. so, there was some change in that allowed us to do it or the puc didn't have that before ~? >> i think it was a combination of factors. one being we had a fairly robust fund balance which made it so you could just cash fund
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stuff. and now as we've eaten into that cash fund balance and as we've seen the cost of doing business increase, that we find we can't enjoy that luxury. so, the plan was to go out into the market and use bond proceeds to fund much of our capital programs. but as the general manager alluded to, we're fag challenges that weren't anticipated when we put that financial plan together. specifically, we're seeing essential capital improvements that we hadn't anticipated. that balanced plan that i just showed you a picture of assumed we were going to spend about $545 million in capital improvements over the 10-year plan. we're expecting now to see an
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increase of 883 million in that 10-year plan. that is largely due to one asset, frankly. we have a tunnel that conveys water from o'shaughnessy dam to our power houses in moccasin. that tunnel is showing signs of deterioration and signs of a major rebuild being necessary to the tune of about $650 million is the estimated cost at this point. so, as i said, that's the largest component of that expected increase. we're also seeing the increases in the pg&e transmission and distribution costs that we just talked about. it's about 16 million a year for the increases for those two cost components. and our current interconnection agreement with them also includes a banking feature that
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we expect to lose which will cost us on net about 2 million or over 4 million, yes. >> commissioner breed. >> thank you. i wanted to go back to the tunnel. it's my understanding that before the bond was introduced that the bond was introduced for puc, i forget what year that was, but that the department was aware of the issues with the particular tunnel, but it wasn't included as part of the bond. so, i just wanted to find out if that were actually the case. >> yeah, it actually predates me, but i heard the same thing so i inquired. as i understand it, unless you'd like to -- >> no, you can go ahead and then i'll add. >> clean up, thank you. the tunnel, you know, the efforts that we went through with the water system improvement program were reliability focused, seismic --
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seismically focused. the problems with the tunnel are not seismically -- it's not related to seismic issues. it's just age. so, it was not included in the water system improvement program because of the difference in scope of the effort. >> the other issue, when we formalized the water system improvement program, is that we really focus on seismic and, so, we looked at facilities that were close by the seismic faults. however, we knew there were some issues with mountain tunnel, so, we have it in the 10-year plan and it's a joint asset, which it's jointly owned by water and power. and, so, we have in our 10-year capital plan about $100 million to go in and reline it. and, so, that was the original plan. and then while going in there, doing more investigation, we had an engineer look at what the impacts would be. and given the fact that it
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could collapse, we are now very concerned that not only we wouldn't be able to produce power, but it would shut off the water supply to san francisco. and, so, when we developed the we step, it was about seismic reliability. and we knew it was an issue with the lining, but we didn't know the magnitude. and, so, we did put the 100 million in our 10 year plan to address it, but we didn't anticipate this much. so, the other thing i wanted to also identify, there are other projects that we've put in the program and they increased in size, like cal var ~ calaveras, for example. we want to let you know once you get involved and start seeing more, some of the scope increases. >> i guess i was just really concerned that since this particular tunnel provides, i guess, over 80% of the water to the bay area and san francisco,
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this kind of concern probably should have been discovered and addressed many years ago. so, i guess i'm just -- now, you know, a significant cost. now it's something of an emergency. now the possibility of it impacting, you know, how we can move forward even with our clean power program and other things just really disturbs me. >> well, let me just point out the water system improvement program we started in 2002, $4.6 billion, we recently invested in that. and i tell you, those projects to me were very important because they're right by seismic faults. and, so, you have to prioritize. the system is over 100 years old. so, we know we need to reinvest in there. we can identify 7, $8 billion we need to invest in there so we need to prioritize. so, we did the best prioritization at the time with the information we knew. we came up with a program with
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$4.6 billion to address that. so, yes, you can look at the system and there may be other parts that are getting old that we haven't really evaluated. the other thing, keep in mind is that you just can't shut down the system and expect the whole system. you have to deliver water most of the year. and, so, it's very rare that we can actually go in these tunnels. for example, irving ton, we haven't shut that tunnel down forever and, so, we, you know, are now able to -- we punched a hole through and we're probably going to bring that online so that we can have a chance and look at irving ton tunnel. we haven't even looked at it, but we knew it was very vulnerable. so, yes, we probably should have looked at it, but just like all the rest of the infrastructure, we just started in 2002 to start addressing these issues. >> and, so, when are we -- are we pro proposing potentially another bond measure to assist us in these efforts or what's the plan? ~ >> so, the plan is we're going to look at what are the
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alternatives. so, right now we're looking at maybe doing a bypass tunnel and that's where the $650 million -- but we're looking at other alternatives to try to reduce the cost. our wholesale customers, water customers are very concerned because you can buy power. you just can't buy that amount of water. and, so, they are very concerned. they're asking us questions about it. and, so, this is one of our top priorities, this mountain tunnel. >> thank you. >> i think commissioner breed's question, though, was around financing. what were you looking at to finance that $6 45 million? >> so, what we wanted to do is currently the asset is ~ a joint asset. 55% is on the power side, 45% is on the water side. and, so, we are looking at how we can finance it given the fact that power enterprise has
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a financial problem. and, so, this is one of the thing that we are working with staff and working internally to first see if we can reduce the cost, look at other alternatives to look at ways that we can assist in financing this so it won't have a major impact on the water side. >> so, why is it that power is 55% water, 45%? it seems like the revenue that's generated from the water side ~ would be much greater than the revenue generated from the power side. i imagine it's like night and day the difference between the two. our water from hetch hetchy come right through the mountain tunnel, right, it doesn't have any other place it goes so it's -- all the water in our system goes through there. seem like that would be the larger bulk of what would be paying for the cost of the mountain tunnel, the water. >> so, it's an agreement that happened in 1985. >> the water sales agreement?
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>> well, where they identify the proportion cost of these assets, 185. what was the rationale? >> you know, we are continuing to research the rationale. i don't have a good answer for that question. >> i would love to hear that rationale. it doesn't make much sense to me, and if there's a way that we can have a new rationale, that would be great. >> and we're looking at that as well because -- but we have to work with our wholesale customers because, of course, they want to make sure they pay their fair share and their definition of fair. and, so, we're starting to have those conversations. >> do you have a sense of when you'll be able to finish those conversations? >> we're moving swiftly on all fronts and this is one of the biggest issues that we're facing. not only on the power side, but on the water side. >> so, then, the final
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challenge is the cost we are incurring to meet new regulatory requirements. the western electric coordinating council, the national electric reliability council implements reliability standards nationwide and within the west. they are an arm of the federal regulatory energy commission and they've gotten much more diligent and involved in how utilities, electric utilities operate their system. electric utility system are interconnected and a problem on one entity system can cascade into another's. with the reliability council, what they're trying to do is make sure that that cascading does not happen and all the systems individually are operated in a way to keep their problems within their own assets. and, so, in order to comply with new rules that are coming out to address those
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reliability concerns, we have included in our ten-year capital plan an increase of 32.4 million to address the needed improvements. so, again, we had anticipated almost 27 million, but with the changes in regulations it needs to increase by 32.4. unanticipated at that level. and as we face all of these challenges, we still have the ongoing obligations and responsibilities that the federal law and the city charter have placed on us to operate our hetch hetchy system responsibly to the benefit of san francisco's businesses and residents. and with a focus on meeting the public interest and the necessity for having a role in electric provision, electric
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service provisions here in san francisco. but though challenge do present consequences that can be quite negative for the city. if we weren't operating our power assets and the city -- the city's general fund were paying pg&e rates, the cost of doing byness for general fund departments would go up by about 50 million each year. for us, this financial circumstance isn't a reliability issue, it's a financial issue. of course, it becomes a reliability issue if we don't address it, but at this juncture we're addressing it as a financial issue and we're confident that we won't go negative given the options and solutions we have before us. but, you know, inaction will have us losing that sheet of
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benefits that i showed you for the city. we will also face, as we move forward, the need to meet bond covenants which does take away some discretion on the part of the city for how it prioritizes its rate making and use of its revenue. and then, you know, inaction would also have us finding a very difficult time in complying with the raker act requirements to operate the system to the benefit of san francisco. how did you that translate into a budget outlook? what you see on this slide is an end of fund balance. so, the end of the year, fiscal year fund balance, how much do we have in our bank account after we've completed a fiscal year.
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we see that tract in the black line for the fiscal year ending 10-13 and beyond, that ten-year outlook at that time, prior to facing these new challenges i just described. when you put the new challenges in with the new capital needs, the new operating costs from transmission distribution, the new regulatory requirements, you find us on the blue line that dives down below zero pretty rapidly over the 10-year horizon. that's the budget outlook problem that we need to focus on solving. and here's some of the options that we are siam am ~ siam sigh mull thaictionviously pursuing. we talked about the fact we'll issue debt in order to fund
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some of those long-lived capital improvements. we're looking at reducing costs. we talked about negotiating with pg&e to the extent we can on some of those operational costs. we're looking at whether there are costs we are incurring today that we could be more efficient and reduce. we're looking at ways to increase rates and we're looking at ways to find new revenue sources, new customers, new customer that fall into that category where they pay us more than it costs us to provide them with service. so, the retail enterprise, commercial type customer. we're also looking at whether there are funding sources for some of the services we provide. we're currently funding, fully funding the service -- street light services that the city enjoys. that's a responsibility we took over when the general fund was having a hard time some years back. and we're looking at whether
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that's -- we could return to the old way of doing it. >> could you give examples again of potential customers of anyone already been courted? >> the most immediate example that comes to mind is the joint transbay power authority, the folk operating the new transit center. they've recently become a new customer of ours. that agreement went through the board approval process and we'll be serving them in 2017. so, we'll see additional revenue from that customer. other sites that we have performed evaluations of, feasibility studies of pursuant to the charter are the hunters point neighborhood as it builds out, the shipyard area, the -- >> i think it has a new name now. >> i'm sorry, i'm probably not up to date on what the -- >> it wasn't a good name, it should be shipyard, but go ahead. >> okay. we were talking about it as a
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new green community when we first started our engagement with them. the other types of customers could be other public agencies that currently self-procure who have expressed interest in potentially working with us as their power provider. so, we're exploring all of those options and pursuing those options. i've redirected some of my staff effort to that in order to bring the dollars in. >> yeah, and i just want to stress how important that is because it's an opportunity now because they are coming to us asking, can we buy power from you? and, so, we are definitely focused and letting everyone know that we have power to sell at a cost where we can, you know, get some revenue to help address our issue. and, so, that is where we redirect staff to really -- to do that. >> thank you. one thing i don't see in your powerpoint is what we're
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expected to generate in terms of looking at new customers in that. like, what our goal is in term of what we currently on average per year generating and when we look at including new customers, what we expect to -- what level we expect to be at. and i also think that it would be good to understand where we're at when we have drought years like we have right now. because we probably are not going to be able to generate enough power this year than if we had cpa transbay joint powers authority already as a customer, we might not able to actually fulfill their demand. >> we expect to fulfill our customers' demand in every year regardless of whether we are self-generating or purchasing in order to meet that need. the cost for power on the wholesale market we would expect will remain below the rates we would charge. and, so, we would never find our self-unable to provide reliable service. for example, when the rim fire occurred, we were directed by
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fire command to dee energize all of our power units in order to protect the firefighting staff ~. we did that. no one here knew the difference because even though we shut off that 380.5 megawatts of generate thattion we were doing or can do, you all still got your power. san francisco airport, all of the general hospital, all of the critical city services, sfmta, all of the critical city services continued to receive service reliably even though we were barred from generating our own electricity. and that's because we have a staff capable of purchasing and selling in the market as we need it. >> who do we purchase from? >> it depends. we look for our good price on the counter party side, folks who are in the market and ready to sell. we are members of the western systems power pool. all of the members are posted online. you can see the various different types of entities
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that sell and buy in that power pool. >> is there a record of who we purchase from? >> absolutely. >> and can i get a copy of who we purchase from? >> sure, sure. it's listed in our annual financial report, our c-a-f-r we publish every year. >> okay, it would be great to get a copy of that as soon as possible. and the other question i have is we're facing a routed year so we are going to meet our customers' demands? are we purchasing power currently because we're not going to be putting as much water through -- >> yes, we are, today we are purchasing a little bit because we're doing some maintenance on the system. it's pretty typical at this time of year before the snow melts, we do some tuning up and make sure we're in good stead on all the up country generating units. it's pretty typical in every year we do some purchasing, some selling. >> are we not taking any additional purchases because of the drought? >> we probably wi